Seismic surveying method

ABSTRACT

An improved method of acquiring seismic data using a plurality of vibratory seismic sources including the steps of deploying a seismic sensor deploying a plurality of vibratory seismic sources at different source points; simultaneously actuating the seismic sources; acquiring seismic data attributable to the seismic sources using the seismic sensor; redeploying at least two seismic sourc, one seismic source being thereby positioned at a source point previously occupied by the other seismic source; simultaneously actuating the redeployed seismic sources; and acquiring seismic data attributable to the redeployed seismic sources using said seismic sensor. The present invention also involves an improved method of acquiring seismic data using a plurality of vibratory seismic sources, where each seismic source is capable of producing seismic energy within given frequency ranges, including the steps of deploying a seismic sensor, deploying a plurality of vibratory seismic sources at different source points; simultaneously actuating the seismic sources in such a manner that the frequency range of the seismic energy produced by one seismic source is substantially outside the frequency range of the seismic energy produced by another seismic source; and acquiring seismic data attributable to the seismic sources using the seismic sensor.

BACKGROUND OF THE INVENTION

This invention relates generally to seismic surveying methods, and moreparticularly to an improved seismic surveying method of using aplurality of vibratory seismic sources.

Seismic vibrators have been used for many years on land to acquireseismic data and many companies have ongoing efforts to utilize similarsources in marine environments. The geophysical and environmentalbenefits of using these types of seismic sources are well known.

When seismic data is acquired utilizing a plurality of vibratory seismicsources, the vibrators are conventionally organized as a travellingsource array. The vibrators are typically placed around or along asource point (also referred to as a “vibrator point” or a “vib point”)with a particular separation distance, such as 40 meters. The vibratorsthen generate a certain number of sweeps that are received by aplurality of seismic sensors, recorded and stacked (i.e. combined) toproduce a seismic data trace for each particular source point/receiverpoint pairing. The vibrators then travel as a group to the next sourcepoint where they are used in a similar manner.

There are several known problems with acquiring seismic data usingseismic vibrators, however, including the need to acquire large numbersof relatively-long records for each source point/receiver point pair toproduce seismic data having a sufficiently high signal to noise ratio.Other known problems with seismic data acquisition using seismicvibrators include harmonics, ground coupling differences, baseplateflexures, and source array effects.

Efforts have been made to address these problems, and one promisingapproach has been the simultaneous use of multiple vibrators atdifferent source points, with each vibrator producing separable, encodedsweeps. One method using this approach, referred to as the High FidelityVibroseis Source (“HFVS”) method, has been developed by Mobil OilCorporation and Atlantic Richfield Company and is described in U.S. Pat.Nos. 5,550,786 (Aug. 27, 1996); 5,570,833 (Dec. 30, 1997); 5,715,213(Feb. 3, 1998); and 5,721,710 (Feb. 24, 1998), all incorporated hereinby reference. The HFVS method was developed primarily to improve thefidelity of vibroseis data.

The HFVS method may be described, in principle, as comprising thefollowing steps:

1. Measuring the vibrator motion S for each vibrator and each sweep,typically using an accelerometer mounted to the vibrator base-plate. Themeasured signal S is related to the true vibrator output U and a minimumphase transfer function T₁. In the frequency domain, the equationdescribing the measured signal S is: S=U*T₁.

2. Recording the seismic data R. This seismic data represents themultiplication in the frequency domain between the earth reflectivity E,the vibrator output U and a minimum phase transfer function T₂:R=U*T₂*E.

3. Obtaining the earth reflectivity at the vibrator location bymultiplying the record R with the inverse of the vibrator motion U:R/U=T₁/T₂*E

For an array of 4 vibrators, V₁, V₂, V₃, and V₄, sweepingsimultaneously, the geophone response R is described in the frequencydomain by the following linear equation: R=m₁₁*h₁+m₁₂*h₂+m₁₃*h₃+m₁₄*h₄.This equation contains 4 unknowns, h₁, h₂, h₃, and h₄ (the earthresponse at the vibrator positions V₁, V₂, V₃, and V₄) and contains theknown values R (the geophone response) and m₁₁, m₁₂, m₁₃, and m₁₄ (themeasured signals).

The unknowns h₁, h₂, h₃, and h₄ can be determined if another 3 sweepsare generated at the same locations and if the sweeps are encoded insuch a way that the measured signal matrix is invertable. The system oflinear equations is:

R ₁ =m ₁₁ *h ₁ +m ₁₂ *h ₂ +m ₁₃ *h ₃ +m ₁₄ *h ₄

R ₂ =m ₂₁ *h ₁ +m ₂₂ *h ₂ +m ₂₃ *h ₃ +m ₂₄ *h ₄

R ₃ =m ₃₁ *h ₁ +m ₃₂ *h ₂ +m ₃₃ *h ₃ +m ₃₄ *h ₄

R ₄ =m ₄₁ *h ₁ +m ₄₂*h₂ +m ₄₃ *h ₃ +m ₄₄ *h ₄

In matrix notation, this can be written as:

R=m×h

where ${R = \begin{bmatrix}R_{1} \\R_{2} \\R_{3} \\R_{4}\end{bmatrix}},\quad {m = \begin{bmatrix}m_{11} & m_{12} & m_{13} & m_{14} \\m_{21} & m_{22} & m_{23} & m_{24} \\m_{31} & m_{32} & m_{33} & m_{34} \\m_{41} & m_{42} & m_{43} & m_{44}\end{bmatrix}},\quad {{{and}\quad h} = {\begin{bmatrix}h_{1} \\h_{2} \\h_{3} \\h_{4}\end{bmatrix}.}}$

The typical implementation of the HFVS method in the field involves onearray or group of vibrators, often four, spread out on an equal numberof consecutive stations or source points. The vibrators sweep a certainnumber of sweeps, let say N (N being greater than or equal to the numberof vibrators) at the same locations. The sweeps have the same frequencycontent but the phase is differently encoded to assure that the matrix Mis invertible. After N sweeps, the vibrators move up a number ofstations equal to the number of vibrators and repeat the sequence.

This implementation of the HFVS method has typically performed well inareas with shallow targets and good signal to noise ratios. For deepertargets or poor signal to noise areas, the standard implementation ofthe HFVS method may not perform well. The number of traces required foreach source/receiver pair (the “fold”) is also quite high, makingacquisition of seismic data using this method relatively expensive.

It is therefore desirable to implement an improved method of acquiringseismic data using a plurality of vibratory seismic sources thatovercomes problems exhibited by prior art seismic data acquisitionmethods.

An object of the present invention is to provide an improved method ofacquiring seismic data using a plurality of vibratory seismic sources.

An advantage of the present invention is that for the same acquisitioneffort and expense, seismic data having a higher signal to noise ratiomay be obtained.

Another advantage of the present method is that if coherent noise in theseismic data is band limited, it may be attenuated only in a particularfrequency range, leaving the remaining frequency components of theseismic data unaffected.

SUMMARY OF THE INVENTION

The present invention provides an improved method of seismic surveyingusing a plurality of vibratory seismic sources, the method including thesteps of:

deploying at least one seismic sensor;

deploying a plurality of vibratory seismic sources at different sourcepoints;

simultaneously actuating said seismic sources;

acquiring seismic data attributable to said seismic sources using saidseismic sensor;

redeploying said seismic sources so that at least one of them ispositioned at a source point previously occupied by another of them;

simultaneously actuating said redeployed seismic sources;

acquiring seismic data attributable to said redeployed seismic sourcesusing said seismic sensor;

decomposing said acquired seismic data into components attributable toeach said seismic source; and

stacking together components attributable to seismic sources located ata common source point.

The invention and its benefits will be better understood with referenceto the detailed description below and the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a process flow chart showing steps associated with theinventive method;

FIG. 2 is schematic plan view of an exemplary seismic data equipmentlayout scheme;

FIG. 3 is an exemplary amplitude versus frequency plot for a pluralityof vibrators;

FIG. 4 is a fold distribution and seismic data section produced using aprior art seismic data acquisition method;

FIG. 5 is a seismic data section produced using the inventivestation-shifting technique; and

FIG. 6 is a seismic data section produced using the inventivestation-shifting and frequency splitting techniques.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 is a process flowchart showing steps associated with the presentmethod. The steps in FIG. 1 will be discussed in connection with theschematic plan view of deployed land seismic acquisition equipment shownin FIG. 2.

As noted in FIG. 1, typically the first step of the method sequence 10is the “deploy seismic sensor” step 12. In FIG. 2, a plurality ofseismic sensors 40, often geophones, are shown deployed along aplurality of parallel lines and connected to a data telemetry cable 42which transmits the output of the sensors to a recording truck 44 wherethe acquired seismic data is recorded and often initially processed.FIG. 2 depicts a typical 3D land seismic survey layout, but it is onlyone of a vast number of alternative seismic sensor deployment schemesthat could be utilized in connection with the inventive method.

Typically the second step of the method sequence 10 is the “deployseismic sources” step 14. In FIG. 2, source points 46 are represented astriangles and four vibrators V₁, V₂, V₃, and V₄ (represented as circles)are being used in this seismic survey. Initially, in this example,vibrator V₁ is located at source point 48, vibrator V₂ is located atsource point 50, vibrator V₃ is located at source point 52 and vibratorV₄ is located at source point 54.

Typically the third step of the method sequence 10 is the“simultaneously actuate seismic sources” step 14, in which all fourvibrators are simultaneously actuated to produce four successive sweepseach. In general, if there are N vibrators, each will be actuated toproduce M successive sweeps, where M is not less than N. The vibratorswill often be both phase and frequency encoded to provide enhancedsignal separability. The phase encoding scheme for could, for instance,comprise the following:

V₁ V₂ V₃ V₄ Sweep 1 90  0 0 0 Sweep 2 0 90  0 0 Sweep 3 0 0 90  0 Sweep4 0 0 0  90. 

Other methods for phase encoding the vibrator sweeps are described inthe references incorporated earlier. This phase encoding assures theinvertibility of the vibrator motion matrix.

To enhance the separability of the signals, the sweep bandwidth is splitamong the vibrators using a frequency splitting technique to provide anadditional degree of orthogonality to the source signals. If the sweepbandwidth required in a certain geologic area is between f₁ and f₂ andan array of four vibrators are used to acquire the seismic data, thebandwidth may be split in the following way.

V ₁ : [f ₁ , f ₁+(f ₂ −f ₁)/4];

V ₂ : [f ₁+(f ₂ −f ₁)/4,f ₁+(f ₂ −f ₁)/2];

V ₃ : [f ₁+(f ₂ −f ₁)/2,f ₁+(f ₂ −f ₁)*3/4];

and

V ₄ : [f ₁+(f ₂ −f ₁)*3/4,f ₂].

Seismic vibrators are, however, typically hydraulically drivenmechanical devices that lack the ability to rigidly cut off theproduction of seismic energy at any particular frequency. Generally theytaper or ramp down the energy produced at the highest and lowest desiredfrequencies. To account for this behavior, referred to as the “sweeptaper”, a small overlap between the bandwidths for each vibrator may bedesirable. This is shown in graphical form in FIG. 3.

As discussed above, the desired range of frequencies is divided by thenumber of vibrators (in this case four) and, in addition, each of thevibrators may be assigned different (and slightly overlapping) frequencyranges. In FIG. 3, the desired range of frequencies is from 8 to 97 Hz.By following the frequency separation scheme described above, vibratorV₁ attempts to produce seismic energy matching the first curve 60 (8-31Hz), vibrator V₂ attempts to produce seismic energy matching the secondcurve 62 (30-53 Hz), vibrator V₃ attempts to produce seismic energymatching the third curve 64 (52-75 Hz), and vibrator V₄ attempts toproduce seismic energy matching the fourth curve 66 (74-97 Hz). Thefirst sweep taper region 68 overlaps the second sweep taper region 70between 30 and 31 Hz. Similar sweep taper overlaps occur between 52 and53 Hz and between 74 and 75 Hz.

In terms of separability of the received signals, it would be preferableto eliminate any overlap of these taper zones. In many cases, however,it is desired to produce a source signal that is spectrally flat, i.e.that has substantially the same amplitude over the entire frequencyrange. If the signal is phase (as well as frequency) encoded, thespectral flatness benefits may overweight the reduction in separabilitythis minor overlapping of the frequency spectra produces. The inventivemethod does not require that a spectrally flat signal be produced,however. In some cases, for instance, it may be preferable to weight orconcentrate the seismic energy with respect to a particular frequencyrange or ranges, particularly if geologic conditions in a particulararea substantially attenuate reflected seismic energy outside a certainnarrow frequency range or ranges.

For each of the four sweeps produced when the seismic sources V₁ to V₄are simultaneously actuated, the seismic sensors 40 will receive theseismic data in the “acquire seismic data” step 18. The seismic data istypically transmitted back to a recording truck 44 where it is recorded,preferably along with signals from respective accelerometers on eachvibrator representative of the vibrator motion.

When the required number of records have been obtained, the seismicsources are redeployed in the “shift seismic sources” step 20. Using oneimplementation of the station-shifting technique, vibrator V₄ is shiftedto source point 56, vibrator V₃ is shifted to source point 54, vibratorV₂ is shifted to source point 52, and vibrator V₁ is shifted to sourcepoint 50. The “simultaneously actuate seismic sources” step 22 and the“acquire seismic data” step 24 are then repeated the required number oftimes for that particular equipment layout.

Typically, the vibrators will continue to produce seismic energy intheir assigned split frequency ranges, as discussed above, but otherfrequency range assignment schemes can easily be envisioned. For sourceseparability reasons, it is important that the frequency range of theseismic energy produced by one simultaneously actuated seismic source besubstantially outside the frequency range of the seismic energy producedby another simultaneously actuated seismic source. Preferably at leasthalf of the seismic energy produced by one seismic source occupies adifferent frequency spectrum than half of the seismic energy produced byanother simultaneously actuated seismic source. As noted above, someoverlapping of the frequency ranges may actually be desirable, but thepurpose of this frequency splitting is to allow the received seismicdata to be decomposed into components attributable to different sourcepoints based, at least in part, on their differing frequency contents.

Path 26 shows that this process is repeated until the required number ofrecords have been acquired for each vibrator for each source point. Thenext time the seismic sources are shifted, vibrator V₄ is shifted tosource point 58, vibrator V₃ is shifted to source point 56, vibrator V₂is shifted to source point 54, and vibrator V₁ is shifted to sourcepoint 52. After the required number of traces are acquired in thisdeployment setup, the vibrators are shifted one more station toward thetop of FIG. 2, and the required number of traces are acquired in thisnew deployment setup. After completing this fourth acquire seismic datastep, it will be appreciated that each of the vibrators (V₁, V₂, V₃, andV₄) have been deployed at source point 54.

Each of the traces acquired by a particular seismic sensor while avibrator was located at source point 54 will then be decomposed orseparated in the “decompose acquired seismic data” step 28. Typicallythis decomposition process results in individual traces for each sweepeach vibrator generated at the particular source point. If fourvibrators are used and they each produced four sweeps at the sourcepoint, there would be 16 output traces, four each in four separatefrequency band groups. Collectively, these four separate frequency bandgroups cover the entire seismic bandwidth required for the seismicsurvey.

To increase the signal to noise ratio of the seismic data, these tracesare combined (“vertically stacked”) in the “stack decomposed seismicdata” step 30. The traces may also be filtered prior to this stackingstep. In some areas, noise, such as ground roll noise or power linenoise, will be frequency band-limited. In these cases it may bedesirable, for instance, to filter the frequency-limited tracescontaining this noise before they are stacked. This may be advantageousbecause noise attenuation methods may be used on the noise affected datawithout fearing that the noise attenuation methods may corrupt theseismic signals in the other sweep frequency ranges. This stackingprocess may consist of merely averaging all of the signals or moresophisticated stacking methods may be used such as the diversitystacking method discussed in U.S. Pat. No. 3,398,396 to P. Embree or thecovariant stacking method discussed in our PCT Patent ApplicationPCT/GB98/03819 (WO 99/32903) to G. Baeten, both of which areincorporated herein by reference. It should be noted that the word“stacking” when used in this context simply refers to combining and doesnot imply normal moveout correction or reduction to zero offset.

A significant advantage of the inventive method compared to prior artseismic data acquisition methods is that the signal to ambient noiseratio of the seismic data may be significantly improved. The signal tonoise ratio of seismic data acquired using vibratory seismic sources maybe calculated using the following equation:

Signal/ambient noise=NV*SQRT(NS*L*W)

where:

NV=number of vibrators;

NS=number of sweeps;

L=sweep length; and

W=sweep bandwidth.

By increasing the number of vibrators deployed at each source point(albeit sequentially, not simultaneously), the number of sweeps and thesweep length can both be reduced while simultaneously improving thesignal to noise ratio of the acquired seismic data.

The separability of the sources is improved using the split bandwidthtechnique because the fundamental for each sweep is different and thefirst order harmonics generated by the third and fourth vibrator do notoverlap the first and second sweep frequencies. The inventive method iscapable of attenuating not only pneumatically introduced harmonics butalso vibrator base-plate/earth interface introduced harmonics.

The amplitude spectrum produced by the vibrators also has larger valuesfor narrow bandwidths and the same sweep length.

Amplitude spectrum=Af*SQRT(T/4*W)

where:

Af=amplitude of the fundamental;

T=sweep length; and

W=sweep bandwidth.

Each of the vibrators is therefore able to transmit a greater quantityof seismic energy into the ground per time unit by limiting thebandwidth swept.

Even if the sweep bandwidth used is the same for each vibrator (i.e. thefrequency splitting technique is not used), the verticalstacking/station-shifting method will still improve the signal toambient noise ratio of the acquired seismic data. When using thevertical stacking/station-shifting technique, any specific vibratorcorrelated noise will be attenuated because the seismic data associatedwith the particular source/receiver pair will consist of data associatedwith each of the vibrators. In addition, the data associated with anyparticular source/receiver pair will typically be acquired over a largertime window, thereby helping to attenuate any ambient noise that is timevariant.

The seismic data produced by the inventive method will then typically besubjected to other seismic data processing techniques such as filtering,migration, etc. that are well known in the seismic data processing art.

The benefits associated with the inventive method were confirmed usingboth synthetic data and in a field experiment. The results of the fieldexperiment, which was conducted in the Delaware Basin, Ward Country,West Tex., are shown in FIGS. 4, 5, and 6. It should be noted that incontrast to the 3D acquisition geometry shown in FIG. 1, these fieldexperiments were conducted using a 2D acquisition geometry, where thesources (vibrators) and the receivers (geophones) are deployed along acommon line.

FIG. 4 shows the results of a conventional 2D HFVS seismic survey. Inthis experiment, four vibrators were used, the sweep frequency was from8 to 96 Hertz, the sweep length was 10 seconds, the number of sweepsproduced at each vibrator point was 8, the receiver interval spacing was200 feet, the shot interval spacing was 50 feet, the listening timeafter each sweep was five seconds, and the number of stations eachvibrator was shifted after completing its sweeps was 4 (200 feet). Ascan be seen in the fold bar chart 80 at the top of FIG. 4, the foldproduced by these acquisition parameters is approximately 60. Theseismic data were then processed using a standard HFVS processingsequence (separation, spiking deconvolution, NMO correction, derive andapply statics, CMP sort, and stack) to produce the reference seismicdata section 82 shown in FIG. 4.

This reference seismic data section 82 can be compared against theimproved seismic data section 86 shown in FIG. 5. In this experiment,many of the parameters used were identical to those used in the previousexperiment: four vibrators were used, the sweep frequency was from 8 to96 Hertz, the receiver interval spacing was 200 feet, the shot intervalspacing was 50 feet, and the listening time after each sweep was fiveseconds. The same vibrators, sensors, and recording equipment were usedfor this experiment and it was conducted over the same area as the firstexperiment. The sweep length was, however, reduced from 10 to 4 seconds,the number of sweeps at each vibrator point was reduced from 8 to 4, andthe number of stations each vibrator was shifted after completing itssweeps was 1 (50 feet). As can be seen in the fold bar chart 84 at thetop of FIG. 5, the fold produced by these acquisition parameters wasapproximately 15 (a four-fold reduction from the previous experiment).The acquired seismic data were then processed using the same processingsequence to produce improved seismic data section 86. Many more coherentreflectors can be seen in this improved seismic data section 86 than inthe reference seismic data section 82.

An experiment was also conducted using both the one-stationstation-shifting technique and the frequency separation technique. Theresults of this experiment are presented in FIG. 6. The only differencebetween this experiment and the previous experiment, the results ofwhich are shown in FIG. 5, is that the four vibrators used separatesweep frequencies of 8-31, 30-53, 52-75, and 74-97 Hz, as discussedearlier. The fold was therefore unchanged, remaining at approximately 15as shown in the fold bar chart 88 at the top of FIG. 6. It should alsobe noted that the seismic data section 90 was created using only the8-31 Hz bandwidth data because the frequency response in the test areawas very narrow. The enhanced seismic data section 90 appears to providean even clearer depiction of the subsurface geology than the improvedseismic data section 86.

It will be readily understood that the steps and processes associatedwith the disclosed embodiment of the present method are capable of awide variety of alternative implementation methods and only a limitedsection from an actual seismic survey is discussed above. The describedexperiments imaged pressure-pressure transmission mode seismic energy,but the method is not limited to this particular seismic energytransmission mode and could, for instance, image pressure-shearconverted transmission mode, shear-shear transmission mode, ormulti-component seismic data. The seismic data acquired may be invertedusing recorded vibrator output (using an HFVS-like method), may beinverted based on a theoretical or optimal vibrator output, or may beprocessed using other types of processing algorithms. The present methodis also in no way limited or restricted to the particular order of stepsdescribed above.

What is claimed is:
 1. A method of seismic surveying using a pluralityof vibratory seismic sources, the method including the steps of:deploying at least one seismic sensor; deploying a plurality ofvibratory seismic sources at different source points; simultaneouslyactuating said seismic sources; acquiring seismic data attributable tosaid seismic sources using said seismic sensor; redeploying said seismicsources so that at least one of them is positioned at a source pointpreviously occupied by another of them; simultaneously actuating saidredeployed seismic sources; acquiring seismic data attributable to saidredeployed seismic sources using said seismic source; decomposing saidacquired seismic data into components attributable to each said seismicsource; and stacking together components attributable to seismic sourceslocated at a common source point.
 2. A method according to claim 1,wherein said simultaneously actuating steps each comprise simultaneouslyactuating each seismic source M times at each source point, where M isnot less than the number of seismic sources.
 3. A method according toclaim 1, further including the step of noise attenuating at least one ofsaid components before said components are stacked together.
 4. A methodaccording to claim 1, wherein the respective outputs of said seismicsources are recorded and used in processing said acquired seismic data.5. A method according to claim 1, wherein said seismic data is invertedusing theoretical or optimal seismic source output.
 6. A methodaccording to claim 1, wherein each said seismic source is capable ofproducing seismic energy within a respective frequency range and thefrequency range of the seismic energy produced by one said seismicsource is substantially outside the frequency range of seismic energyproduced by anon said seismic source when said seismic sources aresimultaneously actuated.
 7. A method according to claim 6, wherein saidseismic sources have sweep tapers and a sweep taper of one said seismicsource overlaps a sweep taper of another said seismic source.
 8. Amethod according to claim 6, wherein the frequency range of one saidseismic source has first order harmonics that do not overlap thefrequency range of another said seismic source.
 9. A method according toclaim 1, wherein said redeploying step comprises shifting said seismicsources one said source point in a common direction upon a common path.